The drilling of a wellbore is typically carried out using a steel pipe known as a drill string with a drill bit at the lowermost end. The entire drill string may be rotated using an over-ground drilling motor, or the drill bit may be rotated independently of the drill string using a fluid powered motor or motors mounted in the drill string just above the drill bit. As drilling progresses, a flow of mud is used to carry the debris created by the drilling process out of the wellbore. Mud is pumped through an inlet line down the drill string, to pass through/over/around the drill bit, and returns to the surface via an annular space between the outer wall of the drill string and the wellbore (generally referred to as the annulus). When drilling off-shore, a riser is provided and this comprises a larger diameter pipe which extends around the drill string, upwards from the well head. The annular space between the riser and the drill string, hereinafter referred to as the riser annulus, serves as an extension to the annulus, and provides a conduit for return of the mud to mud reservoirs. The mud may additionally be used to cool the drill bit, to lubricate the system and power a downhole motor.
Mud is a broad drilling term (known in the relevant art), and in this context it is used to describe any fluid or fluid mixture used during drilling and covers a broad spectrum from air, nitrogen, misted fluids in air or nitrogen, foamed fluids with air or nitrogen, aerated or nitrified fluids through to heavily weighted mixtures of oil or water with solid particles.
Conventionally, the well bore is open (during drilling) to atmospheric pressure with no surface applied pressure or other pressure existing in the system. The drill pipe rotates freely without any sealing elements imposed or acting on the drill pipe at the surface. In such operations there is no requirement to divert the return fluid flow or exert pressure on the system.
During drilling the drill bit penetrates through underground layers of rock and structures until the drill bit reaches one or more reservoirs, also known as formations, pore spaces or voids, which contain hydrocarbons at a given temperature and pressure contained within the rock. These hydrocarbons are contained within the pore space of the rock which may also contain water, oil, and gas constituents. Due to the forces being exerted from the layers of rock above the formations, these formation fluids are trapped within the pore space at a known or unknown pressure, referred to as pore pressure. An unplanned inflow of these formation fluids (also known as reservoir fluids) is well known in the art, and is referred to as a formation influx, or kick.
The mud is a fluid of a given density, also referred to as weight, and, most importantly, is also used to deal with any formation influx (or kick) that might occur during drilling. For example, in a type of drilling known as “overbalanced” drilling, the density of the mud is selected so that it produces a hydrostatic pressure (due to the weight of the mud) at the bottom of the wellbore (the bottom hole pressure, or BHP) which is high enough to counter balance the pressure of fluids in the formation (“the formation pore pressure”), thus substantially preventing inflow (to the wellbore) of fluids from formations penetrated by the wellbore. In other words, the mud acts as a barrier against formation fluid entering the wellbore. The BHP can be varied and controlled by exploiting the relationship between the density of the mud and the vertical extent of the mud within the wellbore, so as to increase or decrease the hydrostatic pressure applied by the mud at the bottom of the wellbore. If the BHP falls below the formation pore pressure, an influx or kick of the formation fluid may occur, i.e. gas, oil or water, can enter the wellbore. Alternatively, if the BHP is too high, it might be higher than the fracture strength of the rock in the formation. Under such circumstances, the pressure of mud at the bottom of the wellbore can fracture the formation, and mud can enter the formation. This loss of mud causes a momentary reduction in BHP which can, in turn, lead to the formation of a kick. Exceeding the formation fracture pressure can also lead to the mud being lost as it flows into the formation. Depending on the magnitude of these losses there is a significant risk that the consequent decrease in the hydrostatic pressure in the well will result in a decreased height/level of mud in the wellbore with a corresponding decrease of the BHP to below the formation pressure. This undesired condition will likely result in a formation influx. These conditions, well known in the art, are also referred to as losses (minor, major, and total/severe depending on the magnitude), or lost circulation.
Another aspect of the BHP exerted by mud is that the BHP has two values associated with it—a static BHP value and a circulating BHP value. The static BHP of the mud relates to the pressure the mud exerts when it is static, i.e. the mud is not being circulated through the drill string. The circulating BHP of the mud relates to the pressure exerted by the mud during circulation of the mud through the drill string, the annulus and through the riser to surface during drilling.
During circulation the pressure exerted by the mud is higher than when it is the static. This is because there are frictional losses over the total length of the wellbore, caused by, for example, the geometry of the drill string relative to the wellbore changing the annular clearance between them or the viscosity or density of the fluid affecting how it flows through the annulus. This reduces the flow rate of the mud. These losses occur from the bottom of the wellbore through to the point at which the mud exits to the surface above ground. Hence, an increased amount of pressure is required to circulate the mud so as to effectively move solids, clean the debris within the wellbore and power the drill bit/string while drilling. The greatest pressure is generated at the bottom of the well bore as at this point the frictional losses along the entire wellbore length have occurred. It is common to relate this increase in circulating BHP to an equivalent circulating density (ECD) mud density which is, for the reasons described, higher than the density of the static mud. Of course, both the ECD and BHP are directly affected by the basic density of the mud.
It is known to have a static mud density that includes a safety factor, i.e. increasing the density of the static mud, and to use this value for both static and circulating conditions such that the BHP is sufficient to prevent a kick occurring.
However, should the system become underbalanced, for example, due to formation influx, it is known to increase the density of the mud so as to increase the BHP of the well bore; thereby reinstating the overbalanced drilling conditions when it is circulated in the wellbore. This mud of increased density is known as kill mud and is circulated so as to fill the entire wellbore and drill string volume. Such operations that are used to reinstate overbalanced drilling conditions may be referred to as well control operations.
Conventional drilling systems aim to maintain the BHP above the pore pressure of the formation but below the fracture pressure of the formation. Managing the BHP in this way is known as Managed Pressure Drilling (MPD).
In managed pressure drilling, the annulus or riser annulus is closed using a pressure containment device such as a rotating control device, rotating blow out preventer (BOP) or riser drilling device. This device includes sealing elements which engage with the outside surface of the drill string so that flow of fluid between the sealing elements and the drill string is substantially prevented, whilst still permitting rotation of the drill string. The location of this device is not critical, and for off-shore drilling, it may be mounted in the riser at, above or below sea level, on the sea floor, or even inside the wellbore. The sealing elements are provided in a housing of the rotating control device (RCD), rotating blow out preventer (RBOP), pressure control while drilling (PCWD), or rotating control head (RCH) used for closing the riser annulus, with the sealing element being in direct contact with the drill pipe. This provides the required isolation of the riser annular from the atmosphere whilst ensuring there is sufficient integrity of the seal against the drill pipe for safe drilling. A typical sealing element in existing pressure containment designs includes an elastomer or rubber packing/sealing element and a bearing assembly that allows the sealing element to rotate along with the drill string. There is no rotational movement between the drill string and the sealing element as the bearing assembly itself permits rotational movement of the drill string during drilling. These are well known in the art and are described in U.S. Pat. Nos. 7,699,109, 7,926,560, and 6,129,152.
A flow control device, typically known as a flow spool, provides a flow path for the escape of mud from the annulus/riser annulus. After the flow spool, there is usually a pressure control manifold with at least one adjustable choke or valve to control the rate of flow of mud out of the annulus/riser annulus. When closed during drilling, the pressure containment device creates a back pressure in the wellbore, and this back pressure can be controlled by using the adjustable choke or valve on the pressure control manifold to control the degree to which flow of mud out of the annulus/riser annulus is restricted.
Managed pressure drilling and/or underbalanced drilling may use equipment that has been specifically developed to keep the well closed at all times to maintain pressures in the well head that are non-atmospheric; unlike the conventional overbalanced drilling method. Thus, managed pressure operations are closed loop systems. Managed pressure drilling also utilizes lighter static mud weights as drilling fluid, as these exert a lower pressure, thereby keeping the BHP below the fracture pressure of the formation—together with surface applied back pressure during drilling to provide the necessary equivalent hydrostatic pressure to prevent the formation influx from entering the wellbore.
Underbalanced drilling allows reservoir fluids to flow to the surface together with the mud/drilling fluid during drilling and tripping. Therefore a pressurized annulus containing hydrocarbons, solids, and drilling fluid exists below the pressure seal of the pressure containment device. Both methods result in a pressurized annulus containing drilling fluids, and/or solids, and/or formation fluids below the seal of the pressure containment device.
Running managed pressure drilling or underbalanced drilling offshore is more difficult than onshore drilling and the degree of difficulty increases when drilling deeper under the sea. This is because the riser section from the seabed floor to the drilling platform becomes an extension of the wellbore and its length is therefore greater with increasing water depth. Therefore the increased hydrostatic pressures generated in the well bore and associated frictional losses substantially increase the ECD of the drilling mud. These increases in ECD can often exceed the formation fracture pressure, at such depths. Furthermore, formation fracture pressures may be lower than seen onshore, and so conventional overbalanced conditions are undesirable due to the high risk of fracturing the formation.
Alternatively, formation pressures in these deep water well situations can be abnormally high, requiring heavier drilling mud weights to balance the well and prevent formation influx. This situation may also cause the circulating/drilling BHP to exceed formation fracture pressures.
These conditions can result in a narrow operating envelope for drilling—also referred to as a narrow drilling margin. It is defined as the small circulating/drilling BHP window resulting from upper and lower constraints from lower fracture pressures and higher pore pressures as the total depth of the well increases. This results in reduced flexibility in the circulating BHP during drilling and/or connections, posing significant challenges.
Therefore offshore, MPD operations are becoming more important for mitigating these risks and increasing overall safety on the drilling platform. A riser sealing solution for MPD allows enhanced pressure control over the riser and a safe diversion of formation influx (if it occurs) through a discharge/control manifold. It also allows lighter drilling mud weights to be used resulting in a decrease in hydrostatic pressure for drilling through lower fracture pressure zones, utilizing surface applied back pressure to impose the additional hydrostatic pressure on the wellbore if required.